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EV Energy Partners LP (NASDAQ:EVEP)

Q4 2010 Earnings Call

March 1, 2011 09:30 am ET

Executives

John B. Walker – Chairman of the Board & Chief Executive Officer of EV Management

Michael E. Mercer – Chief Financial Officer

Mark A. Houser – President & Chief Operating Officer

Ronald J. Gajdica – Head of Engineering and Acquisition

Analysts

Kevin Smith – Raymond James

James Gentile – HITE

Bernie Colson– Oppenheimer

Chad Potter – RBC Capital Markets

Nicholas Schneider – Moore Schneider Management

Richard Roy – Citigroup

Duncan – Private Investor

Mord Ploud – Private Investor

Operator

Good morning ladies and gentlemen, thank you for standing by. Welcome to the EV Energy Partners Q4 and full year 2010 earnings release conference call. (Operator instructions.)

And at this time I would now like to turn the call over to John Walker, Chairman and CEO. Please go ahead.

John B. Walker

Thank you Craig. Good morning from Houston. We’re having a beautiful day; it’d be another 80-degree day. We wanted to do this outside but couldn’t figure out how to do it.

EVEP’s Q4 was in line with our expectations. When I analyzed each of the last four quarters we had some better than expected results in some of our regions in shut-ins, freeze-offs, delays, planned or pipeline issues in some regions every quarter. And of course as you know we didn’t drill wells unless we got a 20% rate of return and that’s hurt us some since the second half of 2008 by enforcing that discipline. Yet our overall results in each quarter tend to balance out and be inline with expectations.

EVEP has an interest in 16,700 wells. I’ll repeat that because it’s important for you to understand. We have an interest in 16,700 wells in eight regions of the country. As a result the vast diversification causes steady results. And Ron Gajadica, our Head of Engineering and Acquisition, Mike Mercer, our Chief Financial Officer, and Mark Hauser our President and Chief Operating Officer will go into more detail about the year and the quarter.

I really want to give you a broader overview of where we are and where we’re going. We more than doubled EVEP’s prude reserves last year with an all-in replacement cost of $1.23 per million Btu and we’re pleased with that.

2011 will be another great year for acquisitions and EVEP will get its share and continue to be disciplined in its purchases. Since 2000 EnerVest has tracked the number of deals in the acquisition sector. Normally it’s about 250 deals per year on which we look at 40 to 60. This past year it was 509, to give you an idea about how active that $50 billion a year was. In January and February are matching last year. So we think it will be another $50 billion dollar year.

Mike will discuss the significant hedges that we’ve added in the last few months for oil and gas in 2013 and 2014. We did two equity offerings last year raising $209 million and received $44 million from asset monitizations in West Virginia and Ohio. In these monetizations we first got cash front end, obviously. We retained a working interest. We got a carry and we’ve kept an override.

Probably our major unrealized asset is Utica Point Pleasant in Ohio. The Point Pleasant is the organically rich lower member of the Utica shell that is present in Ohio but to our knowledge not in Pennsylvania or New York. And this makes a big difference. There are a lot of articles on this potential play and I refer you to a couple of excellent articles. One is the most recent issue of the American Oil and Gas Reporter in which they have two articles on the Utica Point Pleasant. And then last month’s article on the Oil and Gas Investor magazine.

As we and our predecessors have drilled over 500 Knox wells, we have numerous logs of the Utica Point Pleasant and have now taken cores in several parts of Ohio. So we have a pretty clear understanding of where this play is and the quality of play. However, until some horizontal wells are completed and tested this summer, we cannot be 100% sure of its potential. EVEP has exposure to 150,000 net acres in Ohio play and overrides in 80,000 acres. Its acreage is overwhelmingly in the oil and natural gas windows of the play. Now I’d like to turn it over to Ron Gajdica.

Ronald J. Gajdica PhD

Thank you John, we will now discuss our year-end prude reserves. At the end of last year our 2009 SEC approved reserves were 366 Bcf equivalent and now our 2010 year end SEC approved reserves are 817 Bcf equivalent. That is an increase of 452 Bcfe or a 124% increase for the year.

Our reserves are now 70% natural gas, 20% natural gas liquids and 10% oil. The reserves are 71% proved developed and our PV-10 is $1.03 billion. The SEC year-end price that was used for the reserves was $79.43 per barrel of oil and $4.376 per million Btu of gas.

Acquisitions accounted for 436 Bcf equivalent of prude reserve additions during 2010 And the remainder of the revisions in additions accounted for an additional 44 Bcf equivalent. Production for 2010 was 28 Bcf equivalent. Our all-in reserve replacement cost for 2010 was $1.23 per mcf equivalent. Acquisitions, which accounted for most of our reserve additions, were made at a cost of $1.28 per mcf equivalent.

In summary, EVEP has more than doubled its reserves during 2010, has done it at a low cost and has resulted in significant value creation. And now I’ll turn it over to Mike Mercer.

Michael E. Mercer

Thank you Ron. I’m going to briefly go over our full year 2010 and Q4 results then spend a few minutes on our guidance as well as the amount of the significant hedges that we’ve added since the end of Q3 last year.

For 2010 our adjusted EBITDA and distributable cash flow were $148.1 million and $94.2 million. This was a 12% and 24% increase respectively over the prior year. This was primarily due to the acquisitions we made in 2010 as well as some contribution from higher oil and gas prices.

Our production for 2010 was 27.9 Bcfe, which is a 15% increase over the prior year, once again, primarily due to the acquisitions we made during 2010. Our net income for the year was $106.1 million. This included a $40.7 million gain on the sale of unproved acreage earlier in the year. It also includes $3 million of non-cash net unrealized gains on our commodity and interest rate derivatives for the year and $5 million of non-cash compensation costs that were included in the G&A.

In 2009 we had $1.4 million of net income. Now that included $52 million of non-cash, unrealized commodity losses for the prior year and $3.7 million of non-cash compensation expense in G&A for 2009.

For Q4 of 2010 our adjusted EBITDA was $41.6 million, this is a 21% increase over Q4 of 2009 and a 12% sequential increase over Q3 of 2010. Once again, this is primarily related in the sequential increase to the inclusion of our Mid-Continent region acquisition that closed at the end of Q3.

Distributable cash flow as $26.8 million, a 26% increase over the prior year’s Q4 and an 11% increase over Q3 of 2009.

Production was 8.3 Bcfe, a 34% increase over the prior year’s Q4 and a 19% sequential increase over Q3 and increased quarter over quarter over Q3 was primarily from the inclusion of the Mid-Continent region acquisition.

We reported a net loss for the quarter of $14.5 million, however, I’d like to point out that this included $31.6 million of non-cash unrealized losses on our commodity and interest rate derivatives.

Now, if you know, we have significant amount of hedges that run out through 2014 and the $31.6 million non-cash unrealized loss was primarily due to the fact that we have these hedges running out to 2014 and that oil prices increased from the end of Q3 to the end of Q4 and I would point that these are not realized losses on our portfolio. Excluding these losses, we would have had approximately $17 million of net income for the quarter.

Also included for the quarter in net income was $1.6 million of non-cash compensation related expense in G&A and we also had, as you know, when we make acquisitions we do have incremental G&A associated with due diligence and transaction costs and that was approximately $.4 million related to the Barnett Shale acquisition that we closed on December 30th of the prior year.

Now I’d like to turn to guidance. And as you can see we publish guidance, or a range for guidance for 2011 by quarter. We’ve typically, in the past, just shown it for full year period but we wanted to break it out this year by quarter for a couple of reasons. Number one, we have had, as well as other companies, some weather impacts to our production in Q1. It’s approximately about 2%. Mark Hauser is going to be speaking next and will go into a little more detail on that.

And also this year, because of capital level that we’ll have for our drilling program, we do expect increasing production through the year so we wanted to break it out sequentially by quarter so you could see how that will change over time. If you look at the, I’m not going to go through all these measures but I’ll just give you an example on production. If you look at the midpoint of the guidance range, the Q1 production’s about 111 million cubic feet equivalence a day. Q4 midpoints, a little over 122 million cubic feet equivalence per day.

I will summarize the guidance here for the overall year adding up all the quarters and I’m just going to use the mid point of the range to simplify it. But just to give you a sense, for the full year, midpoint of the guidance range, we would have total production of about 42.8 Bcfe or a little over 117 million cubic feet equivalence per day. Price differentials for gas would be 93% off of NYMEX, crude oil 94%, and natural gas liquids 47%. A transportation margin, which as you know is primarily related to our extensive gathering in the Monroe field of about $1.5 million. Lease operating expense of about $68.4 million. Production taxes about 4.6% of revenue, (inaudible) revenue and then G&A of about $20 million and capital expenditures of $72 million. And Mark will speak more about our capital program here in a few minutes.

Next I would like to spend a few minutes on our hedges. What we’ve done in this release is present the hedges that we’ve entered into since the end of Q3 of last year. And then we also show a table after that which shows our overall hedge position as it currently stands.

Just to summarize the hedges that we’ve added here since the end of Q3, for 2011 we’ve added over 9 Bcf of hedges, for 2012 over 5 Bcf and in 2013 over 13 Bcf of natural gas hedges.

On oil, for crude oil, we’ve added about 250,000 barrels for 2011, over 400,000 barrels for 2012, over 500,000 barrels for 2013 and approximately 600,000 barrels for 2014. To give you a sense of it, for 2011 we have hedged approximately 80% of our expected production levels. Now we have also added hedges for 2011 directly for certain NGL products. We were looking at the backwardation (sp) and the risk of NGLs deviating significantly from crude oil. As you know in the past we’ve used crude oil as kind of a dirty hedge for our NGL production and we decided for 2011 for those products that we thought had the most risk of deviating from crude, specifically ethane and propane, to hedge those directly. So we do have ethane approximately 400,000 barrels of ethane for 2011 swabbed and approximately 230,000 barrels of propane for 2011.

Now I would like to turn it over to Mark Hauser to review our operations.

Mark A. Houser

Thank you and good morning everyone. I’m here in Washington and it’s equally as nice here. I don’t know if that’s a good thing or a bad thing but it’s certainly nice to walk outside.

As Mike has described the financial results of 2010 and our last quarter, I’ll spend my time discussing our operational activities and capital plans for 2011 and I’ll finish with a bit more color on our interest position in the Utica.

The last quarter of 2010 and early 2011 has been really dynamic. We’ve integrated another large acquisition and managed through some pretty harsh weather. First to comment on the winter weather and its impact on our 2011 production. As you all know, and I suspect are hearing from other companies that severe winter weather has some impact on our overall production. Our production engineers estimate we were down about 2% for Q1 of 2011 but we’re essentially back up to speed already.

In various areas I would say we were impacted over about a two-week period. The most significant loss was a two-week shut-in of a Southern Union processing plant near our Jalmat field out in the Permian Basin. And then thankfully in Mount Bellview, with the explosion they had there, we were actually very, very minimally impacted.

We continue to believe that the MLPs overall goal, over time is to moderately grow production organically while leaving the dramatic growth to crude acquisitions. We still, as John said, require 20% return on any capital project at current prices. That being said, our 2011 capital program is expected to range between $65 million and $80 million which more than doubled last year’s spending levels and will provide some growth in production as the year progresses. This increase is most attributable to our new Barnett and Mid-Continent acquisitions. About 75% of our total capital will be spent on drilling, 14% on workovers and the balance on land and seismic.

About half of the drilling will occur in the Barnett Shale asset with the Austin Chalk and Mid-Continent areas each taking about 20% of the drilling budget. In Appalachia, our Knox program has the gun and we anticipate activity in the Utica heating up as the year moves forward.

First to our newest acquisition in the Barnett where EVEP acquired a proportionate 31% of the $960 million acquisition. We assumed drilling operations on December 1st and took over productions operations when we closed the transaction on December 30th. Hence December 1st we had drilled seven wells and tried to refract eight wells in a one rig program. I want to emphasize this is in the liquids rich area of the Barnett and our economics are very strong.

As of March 5th we will have a second rig in operations also in the liquid rich area and plan to mostly run two rigs through the balance of the year. We’ve also secured the availability of a fulltime frac crew beginning today. We plan on drilling at least 36 wells this year, which means about 13 net wells through EVEP.

We’re very pleased with our drilling costs, which are running about 20% under our estimated $830,000 per well. At the same time we’re cautious about frac costs are there are some upper pressure. Overall we anticipate these wells will cost around $2.2 million drilled and completed and again, emphasizing that we’re drilling in the liquid rich areas.

Now if I move to the chalk, we currently have a two rig drilling program as we continue both our ongoing naturally fractured horizontal program and our recently initiated multistage frac program. That activity should remain through the year. It consists of last year’s activity and will result in about 18 wells. Of course with our interest on EVEP side of about 17%, that will be able three net wells EVEP.

So now onto our acquisition from Petro (inaudible) which continues to provide additional non-op drilling opportunities. Net production of between $15 million and $16 million per day is consistent with our expectations even into this quarter and there’s a good deal more capital activity as well. We’re mostly in a non-op situation in these properties but the operators including companies such as Apache, SandWind, BP and Chesapeake are very busy with reservoirs such as the (inaudible) the (inaudible) in Cleveland and the (inaudible).

It’s interesting to know that the (inaudible) for capital in 2011 from these properties at around $10 to $12 million for the year. We’ve already received AFEs that we are willing to approve of over $13 million through the last five months. So we see some good growth there.

Eastern division activity, I live back east, the team did a wonderful job last year keeping production at expected levels with somewhat limited capital. We slowed down our Knox drilling, we’re waiting on some 2D and 3D seismic acquisition to further assess other reservoirs adjacent to the Knox but we’ll be kicking back in with some of the Knox activity across all the EVEP’s properties.

On a net basis we’re currently planning to drill about 12 wells for EVEP compared to only two last year when we were evaluating the seismic and kicking off the expanded program.

Last quarter I reported that EVEP participated with 9% security working interest and basically an 8% net revenue in the Goodwynn unit 2-3 horizontal well in Marcellas in West Virginia. It was drilled by (inaudible). (Inaudible) well which again we were carried on and they brought it on at over $7 million a day, in fact (inaudible) $10 million a day is producing over $7 million a day. Petro has planned another well sometime the second or third quarter and EVEP will have a similar interest in that well and will be carried on that well as well.

So finally a few additional comments on the Utica in Point Pleasant. From the evaluation work we’ve done so far, much of EVEP’s approximately 150,000 net acres, at this early stage, appears to be in the oil and liquid window. Through our ten-year history of operations, particularly our wells that have gone to the higher (inaudible) Knox series of sand will have Utica. We’ve collected a good bit of (inaudible) physical data, especially log data that is helping us find in our assessment of Utica. There have been several (inaudible) taken lately that we have or will have access to. There are several wells permitted (inaudible) area that we will have interest in over the next several months which will further refine our strategy.

So generally to summarize, we plan on continuing our good production and cost surveillance that has flattened many of our decline rates in our field and we continue to pursue capital activity similar to past years our existing area, increase our activity in the Barnett and continue to evaluate and refine our overall Utica strategy.

So thanks for you all’s time and John I’ll turn it back to you.

John B. Walker

Thanks Mark. Operator, we’re ready for questions.

Question-and-Answer Session

Operator

(Operator Instructions.) Your first question comes from Kevin Smith of Raymond James. Please go ahead with your question.

Kevin Smith – Raymond James

Thank you. Good morning gentlemen and congratulations on a strong 2010. Mark, can you give us an update on the Barnett? I believe last time we talked there were five wells waiting to be connected to sales and eight wells to be completed. Are all the acquisition backlog wells, are they all online or do you need a cold weather delay in any of that activity?

Mark A. Houser

Yeah, Kevin, we did have some delay. Right now I believe we have one pad that we’ve been drilling wells on over the past quarter and we’re waiting to frac those wells. That frac, those fracs can start, as I said, today. So generally we’re in good shape there. You know, when we talked in our last quarter I think we had a few wells we were ready to bring online. We have fracked and refracked most of those and are now kind of waiting on our next set.

One comment I did make Kevin, which we’re really pleased with, is we actually drilled our last Barnett well and it was a little bit of a shorter interval. As you know, you can have different length horizontal wells depending on where you are in the lease. But our last well, we actually drilled in about seven and a half days which we (inaudible) around 12 days. So we’re really pleased with our progress, we’re really pleased to have our frac crew in place now full time so we expect to have kind of a normal log tied to pad drilling.

Kevin Smith – Raymond James

And are you waiting to complete all the wells on the pad I guess simultaneously?

Mark A. Houser

Not necessarily all the wells, Kevin, on the pad, but typically you have several wells drilled very much where the wellheads are in close proximity to each other. You typically like getting, (inaudible) typically four or five wells at one time that you drill and then you come back and you frac four or five at a time. And there may be ten or twelve wells on path.

Kevin Smith – Raymond James

Gotcha. And you might have mentioned this in your prepared comments; I apologize if I missed it but are there any updates on horizontal drilling activity in San Juan Basin? I believe the end of Q3 you had a well that was just starting to get online.

Mark A. Houser

Kevin we have our one well in Bear Canyon that we drilled and we’re actually about to refract that well. I think I mentioned that we had some problems with that well and we’re about to refract it in one of the intervals that we don’t think we have to crack away on that’s real important to us. And then secondly we’re drilling a well, the EnerVest (inaudible) well that actually I’ll tell you we’re drilling, we’ve drilled it and we’re waiting to frac it. I believe we frac next week on that one, that frac has been delayed due to the weather out there. They’ve had some very prohibited weather out there so that was delayed a bit.

Kevin Smith – Raymond James

Okay. And then one last question. Mike, can you give us any color on the asset sales that EV Energy Partners has done in the second half? I think you mentioned roughly $40 million?

Michael E. Mercer

Yeah, they were primarily the sale of unproved acreage. Almost all of that was almost 100%. Part of it was sale of the Marcellas. The majority was monetization of unproved acreage in Ohio where we retained an interest in those assets. I think it was initially announced back with our Q2 queue back in august when we talked about that.

Kevin Smith – Raymond James

Okay, and that Q2 announcement, that was all $40 million in the second half of 2010?

Michael E. Mercer

Yes, we collected, I believe we collected about half of it in July and we collected the other half, another $20 million in November. And then early in the year we collected the $4 million having to do with the Marcellas.

Kevin Smith – Raymond James

Okay. Thank you very much.

John B. Walker

Kevin, let me emphasize again that while we received cash, we kept a meaningful override on those as well as 25% working interest. So we’re, we still have major participation in that.

Unidentified Company Representative

Well and there’s one addition that 45% working interest has been carried on it as well, a cash carry.

John B. Walker

It does have significant carry. And the other thing on the Barnett, we said this but I’m going to say it over again. We had to be in the natural gas liquids window of the Barnett and so 29% of what we’re getting out of the Barnett is natural gas liquids. And as a result, when we drill a well there, our rates return are in excess of 50%. And to give him an idea on when we bought 29% natural gas liquids range in (inaudible) sale, I think it was about 9% or 10% natural gas liquid. So it does make a major difference in terms of the rate of return whether or not you’re in the dry gas window or whether or not you’re in the liquids window.

Kevin Smith – Raymond James

Absolutely. Thank you gentlemen.

Operator

Thank you. Our next question comes from James Gentile from HITE. Please go ahead with your question.

James Gentile – HITE

Hi guys. Looking forward towards your financing needs, do you see those being met with asset sales like you did partially in 2010 or do you think it might need to go to the dead end or equity markets?

Ronald J. Gajdica

We, as a policy, don’t comment on the financing activities or how we might finance something.

James Gentile – Unidentified

All right, thank you.

Operator

Thank you. Our next question comes from Bernie Colson of Oppenheimer. Please go ahead with your question.

Bernie Colson – Oppenheimer

Hi everyone. It’s interesting that you guys started I guess hedging your NGL directly instead of through crude oil and I was wondering what you could provide for more color on the analysis behind that and why, particularly you’re doing that now, what risks you see out there. Any color would be helpful. Thanks.

Michael E. Mercer

The real risk is if you do a dirty hedge with crude. If you have an event like kind of what’s recently happened with crude moving way up, you could have a dislocation between crude prices and NGL prices. You know, clearly, one of the things people are concerned about with NGLs are the fact that a lot of these shale plays do have a reasonable NGL component to them and so it’s just a supply and demand issue. and clearly the future’s market is saying that NGL prices relative to crude are going to decline. And so the reason we did it directly was from the risk of having some event that would not crude way up some world event that could increase crude prices significantly and yet wouldn’t necessarily have an impact on NGL prices. So you’d be hit with the crude loss on the hedge, crude price loss, and have no real benefit on the NGL side.

John B. Walker

It’s the same philosophy in terms of every time we do say a gas hedge in a region we do a basis hedge. And so because we don’t want to have basis blowout in an area (inaudible). The same thing that’s, you know, natural gas separated from crude, there’s very little relationship now and you are starting to get a separation in actuality in oil and natural gas liquids and we don’t want a basis blow out there. And so that’s the reason for it.

Bernie Colson – Oppenheimer

Okay. That makes sense. And then did you, sorry if I missed this, but did you guys provide what you think the Utica wells are going to cost to drill?

John B. Walker

Some wells are going down right now and obviously the early wells will be more expensive then once you have an experience curve. So we don’t know right now. I think that that’s a better question left for the summer or fall after we drill some. But I can assure you that after wells are drilled and you have a tendency to move your wells around really then drilling off one pad where you get a lot more efficient too. So I’d rather not speculate on that right now.

Bernie Colson – Oppenheimer

Yeah. Okay. Great. Thanks a lot.

Operator

Thank you. Our next question comes from Chad Potter of RBC Capital Markets. Please go ahead with your question.

Chad Potter – RBC Capital Markets

Good morning guys. Sticking with the Utica a little bit, I’m just kind of curious what the, as far as the operatorship goes, will that be predominately EnerVest or EVEP operated. And also just in general what your working interest looks like on average.

John B. Walker

Yeah, the reality is we have 87,000 wells of their Clinton wells in Ohio and we have a working interest that varies between 25% and 100%. And I’m talking about EnerVest overall. And so will we operate some, yes. Do we have a partner, yes. Are we being carried, for the most part yes.

Chad Potter – RBC Capital Markets

Gotcha. Okay. And I guess just a quick modeling question. As far as the CapEx guidance goes in Q3, there’s a pretty big jump up and then a little bit more of a pull back in Q4. Can you provide any color on that, is that just a couple extra wells in one quarter or is there…

Ronald J. Gajdica

It’s just timing of the program Chad. That’s all. There’s nothing to read into that, it’s just timing and when we drill.

John B. Walker

Yeah, and we like everyone else, we’re having some delays in terms of frac crews. I mean there’s only one frac crew right now in the overall San Juan Basin and we were sharing our frac crew in the Barnett and there was some delays in getting to some of these wells and so, you know, this is something that everybody’s facing that we need more (inaudible) capacity and of course there’s a lot of (inaudible) capacity coming on stream. So hopefully by year-end this won’t be as much of an issue as it is today.

Mark A. Houser

Just wanted to comment that first of all the size of EnerVest through the hole is helping us in that regard in some ways to get access to some rigs and such. And secondly, in terms of Q3 versus Q4 there is some degree of we tried to get things done up in back east before Q4 just because the weather tends to cooperate a little bit more in Q3, so there might be a little bit of timing there. But there’s no science beyond that for the timing of the capitals and that’s just, those guidances are taken out of some of our budget data.

John B. Walker

And I think that there’s a phenomena in the Appalachian Basin that is (inaudible) to the Appalachian Basin in that on most of these leases and of course EnerVest overall has an interest in 13,000 wells there and EVEP probably has an interest in 9,000 to 10,000 I don’t know how many wells in Appalachia. And there’s this free house gas cost us something on the order of $4 million or $5 million a day so you actually see that impacting. And I’m talking about EnerVest, I’m not talking about EVEP. And then as the temperature warms up you see that affect fall off. So there is some Q3 to Q4 impact of free gas in the Appalachian Basin.

Mark A. Houser

John, for your information, on a peak basis, during 2011 Q1, house gas net (inaudible) was as high as 1400 (inaudible) at the day at one point. Now that’s reflected in the numbers that we’ve provided but that just puts it in perspective. That’s about, if I recall, of Appalachia’s production, that’s about a couple of percent. So it does have a big impact.

Chad Potter – RBC Capital Markets

I appreciate the color guys.

Operator

And our next question does come from the line of Nicholas Schneider with Moore Schneider Management.

Nicholas Schneider – Moore Schneider Management

Good morning gentlemen. I was wondering if you shared any core data with any other companies on Utica?

Michael E. Mercer

We actually have some joint venture relationships with, one with Chesapeake and in that regard we share information. Otherwise we do not.

Nicholas Schneider – Moore Schneider Management

Okay. And are you going to- the unproved acreage that you sold last year in Ohio, I assume that was perspective for Utica?

Michael E. Mercer

Yes. It was and that’s, again, in one of our joint ventures with Chesapeake where we’re receiving a 25% working interest and override in the carry.

Nicholas Schneider – Moore Schneider Management

Are you planning on sort of continuing to de-risk your position there by obviously it looks like leases are going for $2000 an acre or better or something so this is sort of a potentially a $500 million asset that you would obviously maintain a working interest in. but are you looking to continue to get rid of acreage there or are you sort of encouraged enough by what you’ve seen that you want to hold out for a little while?

John B. Walker

Well again let me point out that we have 8700 of Clinton wells there so all of our stuff is HVP. And we’re not a risk taker. We really like for people to spend the money for drilling wells for us all over the country and then our return on investment is infinite. So, you know, that’s something you’ll continue to see. Now obviously we’ve retained some working interest and once the place de-risk and our carry runs out, we’ll have plenty of cash flow in which to participate. But our approach might be very different from an E&P company but our investors are very different from the investors in the E&P Company and we’ve got to be cognizant of that.

Nicholas Schneider – Moore Schneider Management

Okay, one final question. If you were to have any sort of monetization there or otherwise come into some cash, is there any particular area of the country that you think is particularly attractive whether oil or gas in terms of acquisitions right now?

John B. Walker

Well we’re pretty active in 12 states. We’ve built up concentrations in basins purposefully. This has been a strategy for the last four to five years. Obviously we purposefully built up a big concentration in Ohio. We done the same thing in Austin Chalk and obviously we’ve done the first multistage fracs there this past year. We’re doing things in the San Juan Basin and the Barnett is a new entry for us and we’re still in the initial stages there. I always hate commenting on something where you’ve been operating for about a month and a half but lets just say we’re not disappointed but I’d like to have a little more experience under our feet before we know what’s happening there. But obviously we went into the Barnett, in specifically into the NGL window in Barnett purposefully and you might see some expansion there in that same window.

Nicholas Schneider – Moore Schneider Management

Okay, great. Well thank you very much.

Operator

And our next question comes from the line of Richard Roy with Citigroup.

Richard Roy - Citigroup

Thank you. Good morning. I have a question on acquisition activity. Obviously the last year you required those acquisitions and if I heard correctly it was 509. Could you just comment, is the impetus for these sales still companies looking to fund their (inaudible) projects and the second part of that question would be how has the competitive landscape put these acquisition change for the other figures on (inaudible) or what else are you seeing there?

John B. Walker

I would say there’s been probably very little change from last year. Now there was some impact last year from the private equity guys wanting to sell because of the concern about taxation. I still think that that’s going to be a factor and so we’ll see portfolio companies from some of the private equity guys selling. There’s still quite a bit of selling on the part of the big shale players in terms of financing their shale plays. We see things that have been announced and haven’t been announced that are coming into our shop.

The interesting thing is that our major competition in 2001 through the first half of 2008 were the Chesapeake STO, ZOGs, etcetera and they’re actually now our customers. They’re the ones that are selling the properties. And we’ve been buying from them and so we would expect that to continue. The only new entry into the market would be the very large private equity firms like KKR and BlackStone, (inaudible), etcetera.

Richard Roy - Citigroup

So they’re actually looking to buy the similar type assets as you are?

John B. Walker

Yes but they don’t have a lot of experience in doing that and so that can either be good or bad, you know. Our industry is well known for people coming into the industry without experience and overpaying for assets and that has happened, will continue to happen and we end up of course (inaudible) everything that’s for sale. We’ve, overall in EnerVest we bought between $1.4 billion and $1.5 billion of assets last year. But we bought those for very good rates of return and we’re only going to buy when we achieve our rates of return. And so if somebody wants to overpay for something, they’re going to get it.

Richard Roy - Citigroup

Great. And I’m not sure if I missed it but did you say what portion of the CapEx guidance is going to be spent on maintenance versus growth?

John B. Walker

Mark, you pointed that out.

Mark A. Houser

Yeah well I think what I said is if you look at in terms of growth we don’t really think of it that way, Richard. We feel like we set aside maintenance capital which is really the kind of, the amount of money we expect it takes to maintain production and Mike, if I recall that number itself this year would be around $50 million proforma and (inaudible) spending closer to $65 to $80 which would suggest we have some growth in there. And so by that measure- I mean does that answer your question? There might be an extra $15 million or so, $15 to $25 million ballpark of what we consider growth versus maintenance.

Richard Roy - Citigroup

That’s great. That’s good. And just one last question. What is the corporate decline? I’m assuming with the addition of some of the recent assets, that’s potentially gone up?

Ronald J. Gajdica

It’s estimated, I think our reserve report suggests around 7%.

Michael E. Mercer

Yeah, for the existing assets, the PDP assets, average over the next five years, a 7% decline. Now that’s existing producers. That decline will be essentially neutralized at 0% decline when you look at our puds and PD&Ps that will be added to our production profile.

John B. Walker

But Richard what we’ve got to do is obviously in buying assets your portfolio at times can get too heavily whitted toward PDP and too heavily whitted towards puds and we’re a little too heavily weighted towards puds right now. And we don’t like that and we don’t want to get on a treadmill in terms of drilling and so it’s something we’re extremely cognizant of and so you’ll see us balance that out.

Mark A. Houser

As you know, Richard, overtime since we went public, we’ve always said that we’re very cognizant of both our near term and long term decline rates in which we think it’s very important to keep those at relatively low levels just because of the risk that introduces if you get them up too high into an MLB kind of structure.

Richard Roy - Citigroup

Right. That’s all for me. Thank you.

Operator

(Operator instructions.) Our next question does come from the line of Duncan (inaudible) who’s a private investor. Please go ahead.

Duncan – Private Investor

Good morning. Quick question. What do you see as the impact in your operations of the ongoing controversy concerning the environmental impacts of fracking?

Ronald J. Gajdica

I would say that in the Barnett, the Austin Chalk, we’re not having much of an impact. I think that it’s possible that in the Appalachian basin there will be, as there has been, some impact. We do believe there’s a lot of this information out on hydrofracking. 90% of the gas fills in the United States are fracked. We’ve been doing this for over 50 years. There is not, at least to my knowledge, any incidence in which a frac is actually impacted the fresh water zone. And there is some, I think purposeful, on the part of the environmentalist some misinformation out regarding fracking. Some of that has even been financed by some of the opponents to natural gas. And so I do think though that it’s something that the oil and gas industry is spending a lot of time in terms of education. That’s the reason Mark Hauser’s in Washington DC and we have other people there as we spend time education our congress laters and I do that and others do that. We think it’s a responsibility that we have.

Duncan – Private Investor

Have you seen any potential additional regulatory impacts resulting from that that could affect your operations in areas where you have assets?

Ronald J. Gajdica

Well the regulatory impact that is state by state because hydro fracturing is state regulated. We do have an instance of a former head of an environmental organization now being head of the EPA in Texas that is trying to get publicity where he did something up in the Barnett and clearly did not do his homework, announced an EPA situation that had already been thoroughly investigated by the Railroad Commission and frankly should be very red faced for the information that he provided. So I would say that this is, there’s always an issue in terms of any kind of development whether it’s oil and gas development, real estate development, coal development and so we’ve got to work with the regulators. I think our concern is where do you have extreme environmentalists in regulatory positions that simply want to shut you down. And so far our industry has been able to communicate the importance of natural gas and I don’t think that we’re going to be shut down.

Duncan – Private Investor

My perspective is a little different. I’m retired now and I was a lawyer and I actually represented some utilities who were trying to build nuclear power plants and I’m very familiar with the kinds of issues and problems you guys face. So my concern really was not whether the controversy was right or wrong, my concern really was whether you had seen any immediate impacts on your operations in terms of (inaudible)

Mark A. Houser

Let me comment briefly, probably the biggest thing we could, I’m up here in Washington and it’s a really simple approach to, like I’m meeting with ten different members of congress this afternoon and tomorrow. It’s very simple messages, taxes, fracking and regulation. And getting to the regulation question you had, it seems to me like the biggest area that, as these horizontal fracks are becoming more prevalent in other areas and requiring use of water and what our industry’s working real hard to do is demonstrate to everybody that’s involved and has been faith oriented regulatory action but that we have a plan in place and that we have good actions relative to managing the water. That seems to be the biggest single issue. So our job is going to be just to simply continue to demonstrate how we can handle the amount of water required for fracking, which we’re not the only ones that use water, but we need to let folks know that we’re going to handle it well and dispose of it well. And that’s the biggest area where regulatory could jump in from time to time. But again, so far that’s being managed well.

Duncan – Private Investor

So you haven’t seen any immediate impact in the regulatory sphere of the (inaudible) and the treatment of the wastewater and things like that?

Mark A. Houser

No, we have not.

Duncan – Private Investor

Thanks guys. I mean I know it’s an (inaudible) situation you have to deal with the way you’re dealing with but I was just curious as to whether you’d seen any immediate issues. I appreciate your.

Operator

(Operator instructions.) And our next question does come from the line of Mord Ploud who is a private investor.

Mord Ploud – Private Investor

Hello. I wanted to ask about the increase in crude swabs. I mean it’s, your final year guidance for 2011, it’s only 220 and in 2012 and 2013 it’s going up very sharply.

Michael E. Mercer

Well remember we use crude to do effectively what’s called dirty hedges on our NGL production. Now for 2011 as we mentioned, we directly edged our ethane and propane for 2011. And there’s the possibility that we could move some of those crude swabs to NGLs directly later on. But for years past 2011 we’re using crude to hedge both the crude and the NGL side.

John B. Walker

And you need to remember that our crude hedges for ’11 and ’12 which were very good, by the way, were put in place in 2008, the first half of 2008. Now we’ve added since then.

Mord Ploud – Private Investor

Okay I understand. Another thing I wanted to ask you about was the fact that you report a lot of these things as growth numbers rather than like net production per unit. I’m seeing it’s like it’s gone down between 2010 and 2009. I mean I get that’s partially because of the fact that sometimes you or your (inaudible) the units before and you have to, if they’re going to be there taking their share before you, you have the full benefit of production. But I mean over the long run, as a private investor, I’m looking to see some distribution increase and as long as these numbers are not starting to go up and the Bcf per unit is also down, so I mean I’m, I assume you’re not (inaudible) to look in that (inaudible) I wonder if you could address those issues.

Michael E. Mercer

When we do issue units and we make acquisitions, we want to keep conservative capital structures. I’m not sure that I would say that our distributable cash flow per unit is declining. And as far as increases in muted distributions in the future, we have some that our long term goal over time is to average about 5% and right now we’re not just distributing with a 5% increase but we’ve had a big period of commodity price declines that is maybe starting to bottom our now. You’ve seen some increases in oil and so you’ll start to see, you know, at the appropriate time we’ll address distribution increases.

Mord Ploud – Private Investor

Thank you.

Operator

There are no further questions, I’d like to turn it back for any closing comments.

John B. Walker

Thank you operator. This has been a long call, thank you for staying on the line everyone. I hope it’s been informative to you and I look forward to a great 2011. Thank you.

Operator

Ladies and gentlemen this does conclude the conference call for today. We do thank you for your participation, you may now disconnect your lines at this time.

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